1. Field of the Invention
This invention relates to downhole tools for oil and gas wells and similar applications and more particularly to improved well packers, plugs, and the like.
2. Description of Prior Art
Well packers are used to form an annular barrier between well tubing or casing, to create fluid barriers, or plugs, within tubing or casing, or the control or direct fluid within tubing or casing. Packers may be used to protect tubulars from well pressures, protect tubulars from corrosive fluids or gases, provide zonal isolation, or direct acid and frac slurries into formations.
Typical well packers, bridge plugs, and the like, consist of a packer body. Radially mounted on the packer body is a locking or release mechanism, a packing element system, and a slip system. These packers tend to be two feet or longer depending on the packer design. The packing system is typically an elastomeric packing element with various types of backup devices. The packing system is typically expanded outward to contact the I.D. (internal diameter) of the casing by a longitudinal compression force generated by a setting tool or hydraulic piston. This force expands the elastomer and backups to create a seal between the packer body and casing I.D. This same longitudinal force acts through the sealing system and acts on the slip system. The slip system is typically an upper and lower cone that slides under slip segments and expands the slip segments outwardly until teeth on the O.D. (outer diameter) of a series of slip segments engage the I.D. of the casing. Teeth or buttons on the O.D. of the slip segments penetrate the I.D. of the casing, to secure the packer in the casing, so the packer will not move up or down as pressure above or below the packer is applied. A locking system typically secures the seal and slip systems in there outward engaged position in order to maintain compression force in the elastomer and, in turn, compression force on the slip system. Certain part configurations allow the locking mechanism to disengage to allow retrieval of the packer. The presence of the release mechanism usually classifies the packer as a “retrievable packer” and the absence of the release mechanism classifies the packer as a “permanent packer”.
Problems with prior art packers, in some cases, can be the excessive length of the packers since all of the above combined systems require length. An increased length of the tool results in an increased effort to mill or drill out the tool if and when necessary, particularly at the end of the useful life of the tool. It would advantageous to have a packer that is much shorter in that reduced material would certainly lower material and manufacturing costs. It would be advantageous to have a very short packer, so if packer removal is required, milling time would be greatly reduced.
Some of the drillable frac plugs on the market are the Halliburton “Obsidian Frac Plug”, the Smith Services “D2 Bridge Plug”, the Owen Type “A” Frac Plug, the Weatherford “FracGuard”, and the BJ Services “Phython”. By comparison, all of these plug designs are very long in comparison to the current invention. Also, a very short packer would reduce cost and simplify the task of creating a “Pass-through” packer. “Pass-through” packers are used for intelligent well completions and allow the passage of, for example and not limited to, hydraulic control lines, fiber optic lines, and electrical lines.
Both retrievable and permanent packers are sometimes drilled or milled out of the casing. If the packer is being used as a “Frac Plug”, it is commonly milled out after the frac is completed. Typical packers, as described above, tend to have mill-out problems because the packer parts tend to spin within the engaged slips. The mill operation becomes very inefficient because the packer parts spin with the rotation of the milling tool. Some packer designs exist, for example the BJ Services U.S. Pat. No. 6,708,770, to reduce this spinning tendency. It would be advantageous to have a packer design that would offer alternative features to prevent spinning of parts while milling out. It would also be advantageous if this same design feature would provide a means to equally distribute the slip segments around the packer body to evenly distribute the load on the I.D. of the casing, and also function as packer retrieval devices to retain and retract the slip segments during retrieving.
Another problem is that the slip system is loaded through the packing element system. Any degradation or extrusion of the packing element system reduces stored energy in the slip system thus allowing the slip system to disengage, especially during pressure reversals, the casing and in turn cause packer slippage and seal failure.
Typical packers have a seal system that has elastomers backed up by anti-extrusion devices and the anti-extrusion devices are backed up by gage rings. The gage rings typically have a built-in extrusion gap between the O.D. of the gage ring and the I.D. of the casing to provide running clearance for the packer. The built-in extrusion gap can be a problem and is commonly the primary mode of seal system failure at higher temperatures and pressures. This is because the elastomers and backup devices tend to move into the extrusion gaps. When this movement occurs, the stored energy is lost in the seal system and the seal engagement is jeopardized to the point of seal failure. It would be an advantage to remove the majority of the extrusion gap to prevent the seal from extruding or moving. Attempts have been made to reduce the extrusion gap by use of expandable metal packers, for example, the Baker expandable packer U.S. Pat. No. 7,134,504 B2, US 2005/0217869, and U.S. Pat. No. 6,959,759 B2, or the Weatherford Lamb metal sealing element patent #US 2005/023100 A1.
Typical retrievable packers have slip systems that, when expanded, contact the I.D. of the casing at 45 degree or 60 degree increments around the I.D. of the casing. Each slip segment has a width and there is typically a space between each slip segment. The space between each slip segment creates a surface area where no slip tooth engagement occurs. The total slip contact with the I.D. of the casing may, for example, only be 50% of the surface area on the inside of the casing. If pressure is applied across the packer, the slips are driven outward into the casing. It is a problem in that due to the incremental contact on the I.D. of the casing, high non-uniform stresses in the casing wall can cause deformation or even failure of the casing wall. It would be very desirable to have a slip system that approaches a full 360 degree contact in the I.D. of the casing to minimize damage to the casing. Also, with slip engagement approaching 360 degrees, there is more slip tooth engagement due to increased radial surface contact area, thereby providing the opportunity to reduce length of the slip. Reduced length of the slip then reduces the overall length of the packer.
Typical permanent packers have slip systems that “break”. Slips that “break” approach the 360 degrees of contact. These slips are usually made by manufacturing a ring, cutting slots in the ring to create break points, and then treating the teeth on the O.D. of the ring for hardness purposes. When longitudinal load is applied to a cone, the cone moves under the slip ring and the ring tends to break at the slots to create slip segments. History has shown that the slip segments, break unevenly or don't break at all, break at different forces, and engage the I.D. of the casing in irregular patterns. These breaking problems can reduce the performance and reliability of the packer. It would be advantageous to have slips that approach the 360 degrees of contact and are not required to break, don't require a variable force to break, and evenly distribute themselves around the I.D. of the casing.
Some packers have built-in “boosting” systems. Boosting systems exert additional force on packer seal systems when differential pressure is applied from either above or below, or both, relative to the packer. The additional boosting force tends to help the packer maintain a seal with the I.D. of the casing. The boosting systems typically added to packers require additional parts that add complexity to the packer and require the use of additional seals. Additional seals increase the risk of packer leaks if the seal should fail.
It would be advantageous to have a packer slip/seal design that inherently provides a seal and slip boosting feature, without additional seals and parts, when pressure is applied from either above or below the packer and in which design the slips and seals are arranged in a manner to provide sufficient well sealing and anchoring with component parts which are considerably shorter than those found in conventional packers and similar well plugs.